1. Field of the Invention
This invention pertains to a drilling string member and more particularly to an intermediate weight drill string member.
2. Description of the Prior Art
An intermediate weight drill string member, usually merely referred to as an "intermediate drill stem", can be employed in a drill string for any one of a number of reasons. It is normally employed between the drill collars and the drill pipe in a drill string to provide a gradual transition in rigidity/flexibility between the rigid drill collar parts and the comparatively flexible drill pipe parts.
One application of an intermediate drill stem is to supply weight to the bit in directional drilling. Such a stem provides sufficient flexure to bend around the curves encountered in directional holes without creating high torque and drag which occur when using relatively stiff drill collars. Such a stem is not too flexible, however, so as to provide not too much bending, which is often true of a relatively light drill pipe member alone. Also, such a member does not exhibit as much fatigue as a drill pipe member.
Another application of an intermediate drill stem is that it permits drilling under compression. When drilling vertical holes in relatively soft formations intermediate drill stem members can even be used in place of drill collar members. Drill pipe, on the other hand, is usually driven under conditions of tension and cannot be employed where compression conditions constantly exist.
Thus, an intermediate drill stem normally is employed in a transitional position between the drill collar members and the drill pipe members at a distance of about 600 to 2000 feet above the drill bit for providing some additional weight to the drill collar members where necessary and to prevent compression from being unnecessarily applied to the drill pipe members, the intermediate drill stem location sometimes being under compression and sometimes under tension during a drilling operation.
Virtually all drill pipe employed in oil field drilling includes tool joints, with the working threaded connections being welded to a center tube. Such tool joints or ends normally range in length up to about two feet and, when joined to a tube, make up a drill pipe that is about 30 feet in length. It can be seen that when a tool joint is damaged or otherwise unsuitable for service while the tube is not, it is possible to cut the bad joint off, clean up the remainder of the pipe and add a good joint or end thereto, thereby making a good and whole pipe again.
Both in the orignal making and in the remaking of pipe, the petroleum industry does not accept a weld between the tube or body length of the drill pipe and the tool joint or end which weld has the same cross-sectional area as the tube. This is because the weld and the heat affected zone adjacent the weld has a lower breaking stress capacity than the tube. Therefore, to make the weld as strong as the tube itself, the weld must be thicker.
Most drill pipe used today has an internal upset on each end of the tube to provide the necessary extra thickness where welding takes place. Some tube or body lengths are also slightly externally upset, as well.
U.S. Pat. No. 3,784,238, Chance, et al., shows a tube, the end of which is upset to provide a shoulder in which the weld is made to the tool joint. This shoulder is also the surface which is used for handling of the drill pipe by elevators and slips. Finally, it is known, but not commonly done, to form or upset the end of the tube to be of the same thickness as the tool joint so that the welding is done on the full thickness of the tool joint.
All of these prior art schemes have shortcomings. The most popular weld junction at an internal upset or at an internal upset where there is also some external upset reduces the internal bore dimension of the pipe at the weld and tool joint. When the weld is made at an external upset at a step below the shoulder, the bore is not reduced but the weld is not protected against such things as the creation of a mud ring or from being scarred by the elevators and slips. When an attempt then is made to make a new elevator shoulder by machining away a scarred one, this would be unsatisfactory since the weld area would be machined away as well, thereby reducing the wall thickness at the weld to be the same thickness as the wall of the body of the pipe, which as noted above, it is unacceptable in the industry.
To be acceptable in the industry, an intermediate drill stem should have the following properties: (1) be reasonably flexible, (2) have the same approximate outside geometry as the conventional drill pipe above the intermediate drill stem, and (3) be as heavy per unit length as possible. To elaborate, the intermediate drill stem must be sufficiently flexible that it can bend through curves without creating excessive friction and drag. It must be externally sized so that the same hoisting and handling equipment (e.g., slips and elevators) can be used for both conventional and intermediate drill stem members. The wall thickness should be as great as possible, thereby creating as small a bore as permissible, giving consideration to hydraulic pressure loss and the size of tools that must pass internally through the drill stem.
With the above in mind, the selection of the elevator shoulder for the weld in the intermediate drill stem shown in U.S. Pat. No. 3,784,238 was a logical choice. While this has been a satisfactory design for many commercial applications, there have been three distinct problems with such a location.
As mentioned above, elevator shoulders are subject to wear in service and can become grooved and uneven. Such wear can damage elevators when the seating surfaces do not match. A worn elevator shoulder cannot be machined back without losing the safety factor of the extra thickness of the weld area. Hence, the pipe length must be scrapped when this happens.
Second, all welds on heat treatable steel, from which all modern oil field drill stems are made, should receive some type of post-thermal treatment. Preferred methods of post-thermal treatment cannot be employed to a weld on a tapered surface.
Third, the process control of making a weld on a tapered surface is more difficult than on a straight diameter section. This means that not only is it more expensive to make welds on tapered surfaces, but there is a greater percentage of such welds that fail inspection. When a weld does not pass final inspection, parts can seldom be salvaged.
Therefore, it is a feature of the present invention to provide an improved technique of joining a tool joint or end to a drill pipe that eliminates placing a weld on a shoulder while meeting all the other requirements for an intermediate drill stem.
It is yet another feature of the present invention to provide an improved intermediate drill stem wherein the welding to the tube is not near or in the elevator shoulder, such shoulder also being isolated and protected from wear.
The mathematical analysis of a drill stem member is exceedingly complex. However, in one sense, it can be viewed as a slender column or strut which is subject to Euler's Formula. This formula pertains to the fact that when a load-bearing body in compression has a length more than ten or twelve times its least dimension perpendicular to the load line, simple compression ceases to be the direct cause of failure. Instead, failure occurs as a result of lateral deflections, which, in turn, depends on the modulus of elasticity of the material and the slenderness ratio of the member, as well as the crushing strength of the material. In addition, the load-carrying capacity is dependent on the condition of restraints on the column ends (e.g., guided free end, fixed ends, one end guided and one end fixed, and one end free and one end fixed). A drill stem member is not clearly any one of the above, but safe approximate values can be applied in Euler's Formula to determine the critical buckling load for a drill pipe.
By considering the tool joints or ends as stiff, the prior art intermediate drill pipe would normally have about a four-foot length (two ends each two feet long) and then a twenty-six-foot length (length of the body of the member). Before the critical buckling load was met, such a pipe could flex about 8.7 inches. A 5-inch tube operating in the center of a 10-inch hole would easily contact the wall long before the buckling load was met. A typical diameter of 61/2 inch tool joint would also permit such flexing. Therefore, in U.S. Pat. No. 3,784,238, a wear pad or protector is provided by building up the wall of the body of the pipe length intermediate the ends of the pipe, preferably approximately at the mid point.
As will be noted hereinafter the combined length of the tool joints or ends of the member disclosed herein is approximately ten feet. Hence, for a normal thirty-foot pipe, there is a tube or body length of approximately twenty feet. A 10-foot length, 61/2 inches in diameter would only allow an angling in a 10-inch borehole of about 1.7.degree.. The twenty-foot length would only bend about 0.9 inch before it reached its critical buckling load, which would be far short of contacting the wall of the borehole. Hence, in the present design, there is no need for an intermediate wear pad or protector.
Therefore, still another feature of the present invention is to provide an improved intermediate drill stem not requiring an intermediate wear or protective built-up external surface.